1. Technical Field
Embodiments of the subject matter disclosed herein generally relate to methods and systems for generating, acquiring and processing seismic data and, more particularly, to mechanisms and techniques for de-blending recorded seismic data generated by simultaneously activated plural seismic sources.
2. Discussion of the Background
Seismic data acquisition and processing may be used to generate a profile (image) of geophysical structures under the ground (subsurface). While this profile does not provide an accurate location for oil and gas reservoirs, it suggests, to those trained in the field, the presence or absence of such reservoirs. Thus, providing a high-resolution image of the subsurface is important, for example, to those who need to determine where the oil and gas reservoirs are located.
In the past, conventional land seismic acquisition generally employed multiple vibrators (seismic sources) acting one at a time. In land-based operations, the vibrators are positioned at a source location and then actuated. Once activated, the vibrators generate a sweep that typically lasts between five and twenty seconds and typically spans a predetermined range of frequencies. A recording system that is connected to a plurality of receivers, typically geophones for land-based seismic exploration, is employed to receive and record the response data. For reflection seismology, the record length is typically set to equal the sweep length plus a listen time equal to the two-way travel time, which is the time required for the seismic energy to propagate from the source through the earth to the deepest reflector of interest and back to the receiver. The vibrators are then moved to a new source location and the process is repeated.
For marine seismic acquisition, traditionally, a vessel tows plural streamers having multiple seismic receivers configured to record seismic data. The vessel also tows a seismic source that imparts energy into the water. The seismic energy travels toward the subsurface and is partially reflected back to the sea surface. The seismic recorders record the reflected seismic waves.
When the source (either land source or marine source) is fired, a subsequent recording time is delayed with a delay time so that all useful reflected/diffracted energies are recorded before the next shot is fired. This delay time imposes constraints on the acquisition rate (i.e., slows down the acquisition process) and, hence, increases the cost of acquisition.
To reduce the acquisition time, to increase the shot density, or to increase the illumination of subsurface, it is possible to simultaneously shoot two or more sources. Acquisition of simultaneous source data means that the signals from two or more sources interfere at least for part of the record. By acquiring data in this way, the time taken to shoot a dataset is reduced along with the acquisition costs. As an alternative to reducing the acquisition time, a higher density dataset may be acquired in the same time. For such data to be useful, it is necessary to develop processing algorithms to handle source interference (cross-talk noise).
Source interference appears because subsurface reflections from an early source excitation may be comingled with those that have been sourced later, i.e., a “blended source” survey is acquired. Note that this is in contrast to conventional surveying techniques (discussed above), wherein the returning subsurface reflections from one source are not allowed to overlap with the reflections of another source. Although the blended-source approach has the potential to reduce the time in the field, thereby reducing the cost of the survey, one problem is that it can be difficult to separate the individual shots thereafter. In other words, what is needed in interpreting seismic data is the depth of each reflector, and the depth of a reflector is determined by reference to its two-way seismic travel time. Thus, in a multiple-source survey it is the goal to determine which of the observed subsurface reflections is associated with each source, i.e., to de-blend the data; otherwise, its two-wave travel time cannot be reliably determined.
In this regard, FIG. 1A shows sources being actuated at different spatial positions 10, 12 and 14 with a delay time such that the recorded wavelets 10a-c corresponding to spatial position 10 do not interfere (in time) with wavelets 12a-c corresponding to spatial position 12. The signal recorded at the receiver can be considered as a continuous recording (16) or separated to form regular seismic traces for each individual shot as shown in FIG. 1B. The traces illustrated in FIG. 1B form a receiver gather 20. Each trace in the receiver gather 20 relates to a different shot and has a different position on axis X, and each wavelet has a different time on a temporal axis t.
FIG. 2A shows a similar source configuration as in FIG. 1A, but now the sources are simultaneously activated so that, for example, the wavelet 10c might be superposed (in time) with the wavelet 12a. FIG. 2B shows the receiver gather 30 formed though pseudo-de-blending. Pseudo-deblending involves forming regular seismic traces from the continuous recording based on the start time of the actuation of each shot with no attempt to mitigate cross-talk noise. The data of FIG. 2B has been shot in less time than the data in FIG. 1B, but cross-talk 32 is observed and noise on one trace is signal on another trace.
Thus, for the gather 30 in FIG. 2B, it is necessary to separate the energy associated with each source (de-blend) as a preprocessing step, and then to proceed with conventional processing tools.
Various processing tools for de-blending seismic data are known in the art. However, most of these processing tools involve shot coordinates, either directly or through offset and azimuth. This is a problem because in simultaneous source acquisition, each trace has several shot locations. Simple replication of traces for different shots allows conventional processing but at the cost of undesired energy in the form of leaking noise. Some processes in the seismic sequence are robust enough to handle this noise but some others seem to require a de-blending up-front. Experience on this problem is quite limited, but it is believed that the separation does not need to be perfect, just like noise attenuation is never perfect. In fact the separation may probably only be required in an initial state for noise attenuation and velocity analysis and could probably be reverted before final migration.
Thus, there is a need to develop a method capable of processing blended seismic data while not being limited as noted above.